Hydraulic fracturing methods and systems using gas mixture

ABSTRACT

Systems and methods for fracturing in subterranean formations using treatment fluids that comprise a mixture of natural gas and other gases are provided. In some embodiments, the methods comprise: providing a fracturing fluid comprising a liquid base fluid and a gaseous component comprising natural gas and at least one unreactive gas; and introducing the fracturing fluid into a subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in at least a portion of the subterranean formation.

BACKGROUND

The present disclosure relates to systems and methods for fracturingsubterranean formations.

Treatment fluids can be used in a variety of subterranean treatmentoperations. As used herein, the terms “treat,” “treatment,” “treating,”and grammatical equivalents thereof refer to any subterranean operationthat uses a fluid in conjunction with achieving a desired functionand/or for a desired purpose. Use of these terms does not imply anyparticular action by the treatment fluid. Illustrative treatmentoperations can include, for example, fracturing operations, gravelpacking operations, acidizing operations, scale dissolution and removal,consolidation operations, and the like.

Hydraulic fracturing is one type of treatment operation used to improveproduction from subterranean formations. Fracturing fluids and proppantmaterials may be mixed and pumped through a wellbore and into thesubterranean formation containing the hydrocarbon materials to beproduced. Injection of the fracturing fluid is completed at highpressures sufficient to create or enhance fractures within thesubterranean formation. The fracturing fluid carries the proppantmaterials into the fractures, depositing the proppant materials in thefractures when the fluid flows back out of the well bore. Uponcompletion of the fluid and proppant injection, the pressure is reducedand the proppant holds the fractures open. Upon removal of sufficientfracturing fluid, production from the well is initiated or resumedutilizing the improved flow through the created fracture system.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present disclosure, and should not be used to limit or define theclaims.

FIG. 1 is a diagram illustrating a fracturing system for injecting afracturing fluid mixture of natural gas, unreactive gas, and a liquidbase fluid into a subterranean formation according to at least some ofthe embodiments of the present disclosure.

FIG. 2 is a diagram illustrating a system for controlling the fracturingsystem according to at least some of the embodiments of the presentdisclosure.

While embodiments of this disclosure have been depicted, suchembodiments do not imply a limitation on the disclosure, and no suchlimitation should be inferred. The subject matter disclosed is capableof considerable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The present disclosure relates to systems and methods for fracturingsubterranean formations. More particularly, the present disclosurerelates to systems and methods for fracturing in subterranean formationsusing treatment fluids that comprise a mixture of natural gas and othergases.

The present disclosure in some embodiments provides methods for usingcertain treatment fluids to carry out hydraulic fracturing treatments.Natural gas and an unreactive gas such as nitrogen (N₂), carbon dioxide(CO₂), argon (Ar₂), helium (He₂), or the like may be blended (eitherseparately or as a single gas stream) with a liquid base fluid, andother optional components, to form a treatment fluid, such as afracturing fluid. The fracturing fluid may be introduced into a wellbore that penetrates a subterranean formation at or above a pressuresufficient to create or enhance one or more fractures within thesubterranean formation. The natural gas used in these fracturing fluidsmay be provided and/or stored in any form, including but not limited tocompressed natural gas (CNG) or liquefied natural gas (LNG). Thepresence of the natural gas and/or unreactive gas in the fluid may, insome embodiments, cause the fracturing fluid to form a foam or mist. Thefracturing fluid may comprise a number of other optional components oradditives useful in fracturing treatments, including but not limited toviscosifiers and/or proppant particulates. Following the fracturingtreatment, the gas and accompanying liquid can be recovered, theunreactive gas optionally separated from the natural gas, and theapplied natural gas directed to existing facilities via pipeline forrecovery and sale. In certain embodiments, the unreactive gas may bepresent in sufficiently small amounts (depending on the requirements ofthe natural gas processing facility) that it does not need to beseparated out prior to injection into the pipeline. In certainembodiments, the fracturing systems of the present disclosure mayfurther include gas venting, purging, and/or isolation equipment tofacilitate the operation and maintenance of the system.

Among the many potential advantages to the methods and compositions ofthe present disclosure, only some of which are alluded to herein, themethods, compositions, and systems of the present disclosure may providerelatively unreactive and/or inert fracturing fluids that reduce orminimize chemical damage to the formation being fractured. In someembodiments, the systems of the present disclosure may provide a safeapparatus for preparing the fracturing fluids of the present disclosureand/or introducing them into a subterranean formation. In someembodiments, the natural gas and/or unreactive gases may alter one ormore properties of the liquid base fluid in the fracturing fluid,including but not limited to phase behavior, interfacial tension,viscosity, dissolved gas content, and/or the like.

In some embodiments, unreactive gases such as carbon dioxide may act asa natural solvent, increasing the solubility of methane gas in thereservoir oil. In some embodiments, the unreactive gases may helpdecrease the viscosity of oil and/or other fluids in the subterraneanformation in which they are used, which may increase the mobility ofthose fluids and/or facilitate their production out of the formation. Insome embodiments, the methods and compositions of the present disclosuremay decrease or eliminate the amount of natural gas that must be ventedor flared from a flowback gas prior to injection into a pipeline forprocessing.

The fracturing fluids used in the methods and systems of the presentdisclosure may comprise any base fluid known in the art, includingaqueous base fluids, non-aqueous base fluids, and any combinationsthereof. The term “base fluid” refers to the major component of thefluid (as opposed to components dissolved and/or suspended therein), anddoes not indicate any particular condition or property of that fluidssuch as its mass, amount, pH, etc.

Aqueous fluids that may be suitable for use in the methods and systemsof the present disclosure may comprise water from any source. Suchaqueous fluids may comprise fresh water, salt water (e.g., watercontaining one or more salts dissolved therein), brine (e.g., saturatedsalt water), seawater, or any combination thereof. In most embodimentsof the present disclosure, the aqueous fluids comprise one or more ionicspecies, such as those formed by salts dissolved in water. For example,seawater and/or produced water may comprise a variety of divalentcationic species dissolved therein. In certain embodiments, the densityof the aqueous fluid can be adjusted, among other purposes, to provideadditional particulate transport and suspension in the compositions ofthe present disclosure. In certain embodiments, the pH of the aqueousfluid may be adjusted (e.g., by a buffer or other pH adjusting agent) toa specific level, which may depend on, among other factors, the types ofviscosifying agents, acids, and other additives included in the fluid.One of ordinary skill in the art, with the benefit of this disclosure,will recognize when such density and/or pH adjustments are appropriate.Examples of non-aqueous fluids that may be suitable for use in themethods and systems of the present disclosure include, but are notlimited to, oils, hydrocarbons, organic liquids, and the like. Incertain embodiments, the fracturing fluids may comprise a mixture of oneor more fluids and/or gases, including but not limited to emulsions,foams, and the like.

As used in this disclosure, natural gas refers to methane (CH₄) alone orblends of methane with other gases such as other gaseous hydrocarbons.In some embodiments, natural gas may comprise a variable mixture ofabout 85% to 99% methane (CH₄) and 5% to 15% ethane (C₂H₆), with furtherdecreasing components of propane (C₃H₈), butane (C₄H₁₀), pentane (C₅H₁₂)with traces of longer chain hydrocarbons. As used herein, “CNG” refersto compressed natural gas, and “LNG” refers to liquefied natural gas.

The unreactive gases used in the present disclosure may comprise anygaseous substance known in the art that will not substantiallychemically react and/or will remain substantially inert in theconditions in which it is being used. Examples of gases that may besuitable in certain embodiments include, but are not limited to,nitrogen (N₂), carbon dioxide (CO₂), argon (Ar₂), helium (He₂), and anycombination thereof. The unreactive gas may be provided in a gaseousstate, or may be initially provided in a liquid state and then gasifiedfor use in the fracturing fluids of the present disclosure. Theunreactive gas may be added in an amount of from about 0.01% to about25% of the gaseous stream by total volume of the gaseous stream. In someembodiments, the unreactive gas may be added in an amount of from about0.01% to about 5% by total volume of the gaseous stream.

In certain embodiments, the fracturing fluids used in the methods andsystems of the present disclosure optionally may comprise any number ofadditional chemical additives. Examples of such additional additivesinclude, but are not limited to, salts, surfactants, acids, proppantparticulates, diverting agents, fluid loss control additives, surfacemodifying agents, tackifying agents, foamers, corrosion inhibitors,scale inhibitors, catalysts, clay control agents, biocides, frictionreducers, antifoam agents, bridging agents, flocculants, additional H₂Sscavengers, CO₂ scavengers, oxygen scavengers, lubricants, additionalviscosifiers, breakers, weighting agents, relative permeabilitymodifiers, resins, wetting agents, coating enhancement agents, filtercake removal agents, antifreeze agents (e.g., ethylene glycol), and thelike. In certain embodiments, one or more of these additional additives(e.g., a crosslinking agent) may be added to the fracturing fluid and/oractivated after the viscosifying agent has been at least partiallyhydrated in the fluid. A person skilled in the art, with the benefit ofthis disclosure, will recognize the types of additives that may beincluded in the fluids of the present disclosure for a particularapplication.

The treatment fluids of the present disclosure may be prepared using anysuitable method and/or equipment (e.g., blenders, mixers, stirrers,etc.) known in the art at any time prior to their use. The fracturingfluids may be prepared at least in part at a well site or at an offsitelocation. In certain embodiments, the base fluid may be mixed withcertain components of the fracturing fluid at a well site where theoperation or treatment is conducted, either by batch mixing orcontinuous (“on-the-fly”) mixing. The term “on-the-fly” is used hereinto include methods of combining two or more components wherein a flowingstream of one element is continuously introduced into a flowing streamof another component so that the streams are combined and mixed whilecontinuing to flow as a single stream as part of the on-going treatment.Such mixing can also be described as “real-time” mixing. In otherembodiments, the fracturing fluids of the present disclosure may beprepared in part at an offsite location and transported to the sitewhere the treatment or operation is conducted. In introducing afracturing fluid of the present disclosure into a portion of asubterranean formation, the components of the fracturing fluid may bemixed together at the surface and introduced into the formationtogether, or one or more components may be introduced into the formationat the surface separately from other components such that the componentsmix or intermingle in a portion of the formation to form a fracturingfluid. In either such case, the fracturing fluid is deemed to beintroduced into at least a portion of the subterranean formation forpurposes of the present disclosure.

In some embodiments, a method of forming a fracturing fluid mixture thatcomprises natural gas and an unreactive gas as a gas phase in sufficientquantity to desirably alter the characteristics of the fracturingtreatment is provided. First, a sufficient quantity of natural gas andunreactive gas is made available to complete the fracturing treatment.Fracturing treatments can consume considerable quantities of fracturingfluids with common volumes over 500 m³ (130,000 gal) with unconventionalfracturing consuming volumes in the order of 4,000 m³ (1,000,000 gal).Applying any reasonable quantity of natural gas to the fracturingtreatment can consume anywhere from 50,000 sm³ (1.5 MMscf) to 300,000sm³ (10 MMscf) of gas within a 4 to 6 hour pumping period. To meet thevolume and rate requirement, the natural gas is stored awaiting pumpingfor most applications. Storage of natural gas can be completed by eitherholding it in pressured vessels or by liquefying for storage incryogenic vessels. Efficient storage of natural gas in pressured vesselsis achieved at the highest possible pressure which is typically lessthan 30 MPa (4,400 psi), holding approximately 10,000 sm3 (0.4 MMscf) ineach unit. Effective storage of these quantities even at maximumpressures would require several pressurized vessels with numerousconnections between tanks and pumping equipment at the elevated storagepressures. Alternatively, LNG can be stored in LNG tanks on-site whichpermits considerable volumes to be stored efficiently and at pressuresas low as atmospheric. As a cryogenic liquid one unit volume of LNGcontains approximately six hundred volumes of gas at atmosphericconditions. In a single LNG storage vessel containing 60 m³ (16,000 gal)of LNG, an equivalent of 36,000 sm³ (1.2 MMscf) is stored. A largetreatment would require approximately 10 LNG storage tanks compared toover 30 pressured natural gas tanks. The use of LNG eliminates theissues found with gas phase storage; the multitude of high pressurevessels and piping needed to draw the natural gas from the pressurevessels result in a very complex and potentially hazardous system.

Once provided, the natural gas (and, optionally, the unreactive gas) maybe processed to the fracturing pressure in sufficient quantity.Fracturing pressures are often in the range of 35 MPa (5,000 psi) to 70MPa (10,000 psi), while the natural gas rate is usually from 400 sm³/min(15,000 scf/min) to 1,200 sm³/min (40,000 scf/min). Pressuring thecompressed natural gas to fracturing pressures may require gas phasecompressors of some form.

Alternatively, pressuring natural gas to the extreme pressuresencountered in hydraulic fracturing in liquid form as LNG may be moreefficient. As a liquid the volumetric rates are much reduced andincompressible as compared to gaseous natural gas, compression heatingmay be eliminated and equipment size and numbers reduced. The cryogenicnatural gas liquid is directly pressured to the fracturing pressure by asingle pump, and then simply heated to the application temperature. Foran upper-end fracturing gas rate at pressure, LNG is pumped atapproximately 2 m³/min (500 gal/min) of liquid yielding a gas rate inexcess of 1,500,000 sm³/day (60 MMscf/day) through 8 units of rate to160 sm³/min each. This smaller and simpler equipment configuration maysignificantly reduce the complexity of the operation removing many ofthe costs and hazards which would be present with compressed gastechniques.

After the natural gas (and, optionally, the unreactive gas) is processedto the desired fracturing pressure, the gas stream(s) are combined witha liquid base fluid stream (and, optionally, other additives) to form afracturing fluid that is then injected into the well. The natural gasand unreactive gas may be provided in a single stream that is combinedwith the liquid base fluid stream, or may be provided in separatestreams for combination with the base fluid stream. A mixer can be usedto combine the streams in a high pressure treating line prior to or atthe wellhead; this approach may allow easy handling of the separatestreams without disruption to typical fracturing operations, completethe task without modification to the well, and/or provide a simple andeffective way to accomplish mixing the natural gas and liquid-slurrystreams.

Alternatively, the liquid base fluid stream can be combined with the gasstream(s) in a low-pressure process or within the wellbore at fracturingpressure. The gases are injected down one or more conduits within thewellbore and the liquid-slurry down another conduit with the streamscombining at some point in the wellbore. In these cases, some type of aspecialized wellhead or wellbore configuration in the form of anadditional tubular and a common space is provided where the streams canmeet.

In some embodiments, a fracturing system is provided that includesequipment for storing the components of the fracturing fluid, equipmentfor injecting the fracturing fluid into a subterranean formation, suchas an oil well or a gas well, and equipment for recovering andseparating fluids from the well. In some embodiments, the natural gassource is compressed gas (CNG) held in pressurized vessels with afracturing pump further compressing the natural gas to a suitablefracturing pressure. In other embodiments, the compressed gas is held inpressurized vessels above the fracturing pressure and simply releasedinto the fracturing stream. In some embodiments, the gas source is avessel containing liquefied natural gas (LNG) with the fracturing pumppressuring the LNG to fracturing pressure and heating the pressurizedLNG stream.

FIG. 1 is a generic depiction of the main components of a fracturingsystem 100 according to certain embodiments of the present disclosurewhich use a fracturing fluid comprising a liquid base fluid portion anda gaseous portion that comprises natural gas and an unreactive gas, andmay further comprise proppant particulates and/or one or more chemicaladditives. A liquid base fluid is stored in a liquid tank (13), proppantis stored in a proppant container (12), and chemical additives such as aviscosifier is stored in a chemical additive container (22). Liquid tank(13) suitable for water or hydrocarbon based liquids is connected via aconduit (26) to a fracturing blender (14) with viscosifying chemicalsadded via a conduit from chemical additive container (22). Thefracturing liquid tanks (13) can be any of those common within theindustry for hydraulic fracturing and may apply more than one tank orother suitable arrangement to store sufficient liquid volume. Theconduit (26), like all other conduits shown in FIG. 1, comprises a pipeor hose rated to the described application and conditions. The blender(14) receives the viscosified fracturing liquid and blends proppantmaterial from a proppant supply container (12) with the fracturingliquid to form the base fluid which is now in a slurry form. The blender(14) is a multiple task unit that draws liquids from the liquids tankwith a centrifugal pump (not shown), accepts chemicals from the chemicaladditive container (22) and mixes them with the liquid base fluid, oftenwithin the centrifugal pump. The liquid base fluid is combined withproppant from proppant supply container (12) in a mixing tub or othermixing device on the blender (14) to form a slurry, and then drawn intoanother centrifugal pump mounted on the blender (14). The created slurryis then pumped via a conduit (50) from the blender (14) to a highpressure slurry pump (16). The high pressure slurry pump (16)pressurizes the liquid stream to a suitable fracturing pressure and isconnected via conduit (42) to a fracturing fluid mixer (18). In someembodiments, more than one pump may be used as the pump (16). In someembodiments, certain of the foregoing components may be combined such asthe blender (14) and high pressure slurry pump (16).

Natural gas is stored in a natural gas container (15) and a natural gasstream is pressurized and supplied by a high pressure natural gas pump(17) and enters a fracturing fluid mixer (18) via a conduit (24). Thenatural gas stored in container (15) can be compressed natural gas orliquefied natural gas. An example of a vessel applied for compressednatural gas transport and storage is the trailer mounted LincolnComposites' TITAN Tank holding up to 2,500 scm (89,000 scf) of CNG atpressures to 25 MPa (3,600 psi). An example of a vessel applied forliquefied natural gas storage is the skid mounted EKIP Research andProduction Company LNG Transporter with a capacity of 35.36 m3 (9,336gal) holding up to 21,000 scm (750,000 scf) of liquid natural gas atpressures to 0.6 MPa (90 psi). LNG is typically stored at atmosphericpressure at a temperature of approximately −162° C. (−260° F.).

The high pressure natural gas pump (17) comprises a compressor ifcompressed natural gas is the source or a specialized liquefied naturalgas fracturing pump and a heating component to vaporize the LNG if LNGis the source. The output from the high pressure natural gas pump (17),regardless of the state of the source gas, is in a gaseous state. Insome embodiments, more than one pump may be used as the pump (17). IfCNG is the natural gas source, the high pressure natural gas compressorpump (17) is used to compress the gas to the fracturing pressure, ifnecessary. Compression may be accomplished by any pump capable ofincreasing the pressure within a gas stream; for example reciprocatingcompressors may be applied to achieve high pressure such as thatrequired for hydraulic fracturing. Typically compressors achieve a fixedcompression factor, such that multiple stages of compression may berequired to attain fracturing pressure. Similarly, in order to achievethe desired rate, multiple of compressor stages may be applied inparallel. If LNG is the natural gas source, the high pressure naturalgas pump (17) may be arranged to pressure the LNG to the fracturingpressure (e.g., using a pump component) and then heat the pressured LNGto compressed gas (e.g., using a heater component, such as a flamelesscatalytic heater comprising at least one catalytic element fluidlycommunicable with and capable of oxidizing a fuel gas to generate heat).

An unreactive gas such as nitrogen (N₂), carbon dioxide (CO₂), argon(Ar₂), helium (He₂), or the like is stored in gas source (30). The gassource (30) can contain a cryogenic unreactive gas cooled to pre-coolthe high pressure natural gas pump or other equipment prior tointroducing the natural gas. This may reduce or eliminate the need topre-cool the system using flammable natural gas and eliminates thenatural gas flaring otherwise needed. The unreactive gas from gas source(30) can be introduced into conduit (23) via conduit (32) upstream ofthe natural gas pump (17), and/or into conduit (24) via conduit (34)downstream of the natural gas pump (17). In the former embodiments, thepump (17) may be used to pressurize and/or heat the unreactive gas alongwith the natural gas. In the latter embodiments, the unreactive gas maybe pressurized and/or heated separately prior to its introduction intoconduit (24), for example, using separate high pressure pumps, heaters,etc. (not shown).

Within the mixer (18), the gas stream from conduit (24) is combined witha liquid fluid stream from conduit (42); this liquid can comprise theliquid base fluid optionally combined with proppant and/or chemicaladditive(s). As described above, the gas stream from conduit (24) maycomprise both the unreactive gas from gas container (45) and natural gasfrom the high pressure natural gas pump (17). Alternatively, theunreactive gas can be provided to mixer 18 in a gaseous stream separatefrom the gaseous stream comprising the natural gas, for example, via aseparate conduit (not shown). The combined fracturing fluid then entersa well (19) via a conduit (25) where it travels down the well bore tothe formation creating or enhancing the hydraulic fracture using therate and pressure of the fracturing fluid. Upon applying the desiredfracturing materials within the well (19), injection is stopped andplacement of the fracturing treatment is complete. Following thefracture treatment and at a time deemed suitable for the well, the well(19) is opened for flow with the stream directed to a conduit (20 a) andthen through a separator vessel (60) wherein gases are separated fromliquids. Initial flow from the well will be mostly comprised of theinjected fracturing materials and the separator vessel (60) is used toseparate the injected natural gas from the recovered stream through theconduit (20 a). The liquids and solids recovered from separator vessel(60) are directed to tanks or holding pits (not shown). The natural gasfrom the recovered stream exits the separator (60) and is initiallydirected to a flare (20), e.g., through a flare conduit line fluidicallycoupled to the separator (60), until flow is suitably stabilized, and/orto remove any of the unreactive gas from the natural gas stream. Oncethe natural gas stream is stabilized, it may be directed to a pipeline(21) for processing and sale. In some embodiments, the relative amountsof natural gas and/or unreactive gas in the gas stream(s) provided tothe mixer 18 may be determined based at least in part on flow backrequirements for the gas being directed to the pipeline (21) forprocessing and/or sale, such that the natural gas and unreactive gas canbe directed to the pipeline without removal of the unreactive gas,venting of the natural gas and unreactive gas, or flaring of the naturalgas and unreactive gas. In these instances, the system 100 may omit theflare 20 and/or other separation equipment.

A number of control valves (V1) through (V13) may be selectively openedand/or closed to control the flow of liquids, gases, and othercomponents through the conduits shown in the system 100. For example,feed valve (V4) may be selectively opened and/or closed to a desireddegree to regulate the supply of pressurized natural gas flowing fromits source (15) to the natural gas stream slurry mixer (18). Fracturingliquid control valve (V1) may similarly regulate flow from thefracturing liquid tank (13), proppant supply valve (V2) may regulateflow of proppant from proppant supply (12), chemical supply valve (V10)may regulate flow of chemical additives from the chemical source (22),and fracturing blender valve (V3) may regulate flow from the fracturingblender (14) in order to supply a properly constructed liquid mixturesor slurries to the high pressure slurry pump (16). Additional valves(not shown) may be present in system 100, among other purposes, tocontrol venting or purging operations, and to monitor the condition ofsystem components.

In some embodiments the fracturing systems of the present disclosure canfurther include equipment for venting, purging, and/or isolating naturalgas (“venting, purging and isolation equipment”). Among other benefits,such equipment may aid in controlling the risks associated with naturalgas being a flammable high pressure gas source. The equipment caninclude use of a cryogenic inert gas cooled to pre-cool the highpressure natural gas pump or other equipment prior to introducing thenatural gas. This reduces or eliminates the need to pre-cool the systemusing flammable natural gas and eliminates the natural gas flaringotherwise needed. In some embodiments, an inert gas can also be used topressure test the fracturing system to identify any leaks or failures,or permit any configuration or function testing of the system, or toquickly purge any residual natural gas, oxygen, or air before, during orafter fracturing treatment. In the event of a leakage or componentfailure during fracturing treatment, the venting, purging and isolationequipment allows for that component to be isolated so that the remainderof the system is unaffected. The venting, purging and isolationequipment may comprise a series of additional valves and supply conduitsto deliver purging gas to, or vent gas from, various points in thesystem. In some embodiments, the venting, purging and isolationequipment also may comprise a purge gas supply. In some embodiments, theunreactive gas supply (30) may be used as a purge gas supply, forexample, when it is not being used to supply the unreactive gas to thefluid introduced into well (19).

In some embodiments, the operation of a fracturing system of the presentdisclosure (including any purging or venting equipment therein) may becontrolled by a controller. FIG. 2 is a diagram illustrating a systemfor controlling the fracturing system of some of the embodiments. Thecontroller (58) has a memory programmed to control the operation of atleast some components within the system. The controller (58) maycommunicate with components in the system by direct connection orwireless connection to the various components. For example, fracturingblender (814), high pressure natural gas pump (817) and high pressureslurry pump (816) may be remotely controlled by such a controller. Oneor more of valves (V18) through (V138) (which may correspond to valvesV1 through V13 shown in FIG. 1) also may be connected to and remotelycontrolled by such a controller (58). Among other benefits, remotecontrol capability may permit ready and reliable control of theoperation from a central point plus allows control of the system duringnormal operations, and in particular an emergency, without exposingpersonnel to hazards. The controller also may ensure a properlyproportioned mixed natural gas and liquid slurry stream is created bycontrolling the relative supply of the gas fracturing stream compared tothe liquid slurry stream by control of the high pressure slurry pump(16) and the high pressure natural gas pump (14). Control of thecomponents may be directed by either the operator of the system via auser interface or through software containing algorithms stored on thememory of the controller and developed to direct the components tocomplete the task in a suitable manner. The controller may be anysuitable process control system and may include control inputs fromoperator panels or a computer. Similar control capability is applicableto other described configurations and other components as required.

For example, the controller (58) is connected to and controls theoperation of the feed valve (V48) and the high pressure natural gas pump(817) thereby controlling the supply of pressurized natural gas from itssource (815) to the natural gas stream slurry mixer (18). Concurrently,controller (58) is connected to and controls the operation of thefracturing liquid control valve (V18) to regulate flow from thefracturing liquid tank (813), the proppant supply valve (V28) toregulate flow from proppant supply (812), the chemical source (822) andthe fracturing blender (814) in order to supply a properly constructedliquid slurry to the high pressure slurry pump (816). Simultaneouscontrol functions continue with controller (58) connected to andcontrolling high pressure slurry pump (816). Controller (58) may furtherensure a properly proportioned mixed natural gas and liquid slurrystream is created by controlling the relative supply of the natural gasfracturing stream compared to the liquid slurry stream by control of thehigh pressure slurry pump (816) and the high pressure natural gas pump(814). Controller 58 is connected to and controls the operation of thefeed valves (V118) and (V128) thereby controlling the supply ofunreactive gas from its source (830) to the high pressure pump (817)and/or the mixer (18) (as shown in FIG. 1).

In the system shown in FIG. 1, or other systems of the presentdisclosure, one or more of the above-described components (e.g., theliquid base fluid tank, natural gas source, chemical additive source,proppant source, unreactive gas source, blenders, pumps, controllers,and/or user interfaces) may be mounted on a series of mobile trucks orother surface equipment that can be located at the surface at a wellsite, among other reasons, to facilitate the transport of that equipmentto and from a well site. The configuration and apparatus on any one unitcan be altered or the equipment may be temporarily or permanentlymounted as desired. Moreover, similar systems may be used in matrixstimulation treatments such as acidizing treatments or scale removaltreatments. In those treatments, the systems of the present disclosuremay be used to introduce a treatment fluid comprising a liquid basefluid, natural gas, and an unreactive gas at a pressure appropriate tothose treatments.

An embodiment of the present disclosure is a method comprising:providing a fracturing fluid comprising a liquid base fluid and agaseous component comprising natural gas and at least one unreactivegas; and introducing the fracturing fluid into a subterranean formationat or above a pressure sufficient to create or enhance one or morefractures in at least a portion of the subterranean formation.

Another embodiment of the present disclosure is a method comprising:providing a liquid base fluid; providing gaseous natural gas; providingat least one gaseous unreactive gas; mixing the liquid base fluid, thenatural gas, and the at least one unreactive gas to form a fracturingfluid; and introducing the fracturing fluid into a subterraneanformation at or above a pressure sufficient to create or enhance one ormore fractures in at least a portion of the subterranean formation.

Another embodiment of the present disclosure is a system comprising: aliquid base fluid source; a liquid base fluid pump fluidly coupled tothe liquid base fluid source for pressurizing a liquid base fluid to atleast a pressure sufficient to create or enhance one or more fracturesin at least a portion of a subterranean formation; a natural gas source;a natural gas pump fluidly coupled to the natural gas source; anunreactive gas source; and a mixer for mixing the liquid base fluid,gaseous natural gas, and gaseous unreactive gas to form a fracturingfluid mixture for injection into a wellhead at a well site comprising awell bore penetrating at least the portion of the subterraneanformation, the mixer having at least a first inlet fluidly coupled tothe liquid base fluid pump, a second inlet fluidly coupled to thenatural gas pump, a third inlet fluidly coupled to the unreactive gassource, and an outlet fluidly coupled to the wellhead.

Another embodiment of the present disclosure is a method comprising: (a)providing a liquid base fluid and pressurizing the base fluid to atleast a fracturing pressure of the formation; (b) providing liquefiednatural gas (LNG) and pressurizing the LNG to at least the fracturingpressure then heating the LNG until the LNG is vaporized to a gaseousstate; (c) providing at least one unreactive gas and pressurizing theunreactive gas to at least the fracturing pressure; (d) mixing thepressurized liquid base fluid, pressurized gaseous natural gas, andpressurized unreactive gas to form a fracturing fluid; and (e) injectingthe fracturing fluid into a well bore penetrating at least a portion ofa subterranean formation to create or enhance at least one fracture inthe subterranean formation.

Another embodiment of the present disclosure is a system for generatingan energized fracturing fluid mixture for hydraulically fracturing adownhole formation, the system comprising: (a) a fracturing base fluidsource; (b) a base fluid pump fluidly coupled to the fracturing basefluid source, and configurable to pressurize a liquid base fluid to atleast a fracturing pressure of a formation; (c) a liquefied natural gas(“LNG”) source; (d) an LNG pump assembly fluidly coupled to the LNGsource and comprising a pump component configurable to pressurize LNG toat least the fracturing pressure, and a heater component configurable tovaporize pressurized LNG to a gaseous phase; and (e) a fracturing fluidmixer having a first inlet fluidly coupled to the base fluid pump, asecond inlet fluidly coupled to the LNG pump assembly and an outlet forcoupling to a wellhead, and for mixing the liquid base fluid and gaseousnatural gas to form a fracturing fluid mixture for injection into thewellhead.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. While numerous changes may be made bythose skilled in the art, such changes are encompassed within the spiritof the subject matter defined by the appended claims. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered or modified and all such variations are considered within thescope and spirit of the present disclosure. In particular, every rangeof values (e.g., “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values. The terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a fracturing fluidcomprising a liquid base fluid and a gaseous component comprisingnatural gas and at least one unreactive gas; and introducing thefracturing fluid into a subterranean formation at or above a pressuresufficient to create or enhance one or more fractures in at least aportion of the subterranean formation.
 2. The method of claim 1 whereinthe unreactive gas comprises at least one gas selected from the groupconsisting of: nitrogen (N₂), carbon dioxide (CO₂), argon (Ar₂), helium(He₂), and any combination thereof.
 3. The method of claim 1 furthercomprising: vaporizing liquefied natural gas (LNG) to form the naturalgas.
 4. The method of claim 1 wherein the natural gas is provided ascompressed natural gas (CNG).
 5. The method of claim 1 wherein theunreactive gas is present in an amount of from about 0.01% to about 25%by total volume of the gaseous component.
 6. The method of claim 1wherein the unreactive gas is present in an amount of from about 0.01%to about 5% by total volume of the gaseous component.
 7. The method ofclaim 1 further comprising: flowing at least a portion of the gaseouscomponent comprising the unreactive gas out of the subterraneanformation to a pipeline having at least one end disposed proximate to awell bore penetrating the subterranean formation.
 8. A methodcomprising: providing a liquid base fluid; providing gaseous naturalgas; providing at least one gaseous unreactive gas; mixing the liquidbase fluid, the natural gas, and the at least one unreactive gas to forma fracturing fluid; and introducing the fracturing fluid into asubterranean formation at or above a pressure sufficient to create orenhance one or more fractures in at least a portion of the subterraneanformation.
 9. The method of claim 8 wherein the at least one unreactivegas is provided in a first gaseous stream and the natural gas isprovided in a second gaseous stream that is different from the firstgaseous stream.
 10. The method of claim 9 wherein the method furthercomprises mixing the first gaseous stream and the second gaseous streamto form a mixed gaseous stream, and the step of mixing the liquid basefluid, the natural gas, and the at least one unreactive gas comprisesmixing a liquid stream comprising the liquid base fluid with the mixedgaseous stream to form the fracturing fluid.
 11. The method of claim 9wherein the step of mixing the liquid base fluid, the natural gas, andthe at least one unreactive gas comprises mixing a liquid streamcomprising the liquid base fluid with the first gaseous stream and thesecond gaseous stream to form the fracturing fluid.
 12. The method ofclaim 8 wherein providing gaseous natural gas comprises vaporizingliquefied natural gas (LNG) to form the gaseous natural gas.
 13. Themethod of claim 8 wherein the unreactive gas is present in thefracturing fluid in an amount of from about 0.01% to about 5% by totalvolume of a gaseous component consisting of the natural gas and theunreactive gas.
 14. The method of claim 8 wherein the unreactive gas ispresent in the fracturing fluid in an amount of from about 0.01% toabout 25% by total volume of a gaseous component consisting of thenatural gas and the unreactive gas.
 15. The method of claim 8 furthercomprising: providing a proppant material; and mixing the proppantmaterial with the liquid base fluid prior to mixing the liquid basefluid with the natural gas and the at least one unreactive gas.
 16. Themethod of claim 8 further comprising: flowing at least a portion of thegaseous component comprising the unreactive gas out of the subterraneanformation to a pipeline having at least one end disposed proximate to awell bore penetrating the subterranean formation.
 17. A systemcomprising: a liquid base fluid source; a liquid base fluid pump fluidlycoupled to the liquid base fluid source for pressurizing a liquid basefluid to at least a pressure sufficient to create or enhance one or morefractures in at least a portion of a subterranean formation; a naturalgas source; a natural gas pump fluidly coupled to the natural gassource; an unreactive gas source; and a mixer for mixing the liquid basefluid, gaseous natural gas, and gaseous unreactive gas to form afracturing fluid mixture for injection into a wellhead at a well sitecomprising a well bore penetrating at least the portion of thesubterranean formation, the mixer having at least a first inlet fluidlycoupled to the liquid base fluid pump, a second inlet fluidly coupled tothe natural gas pump, a third inlet fluidly coupled to the unreactivegas source, and an outlet fluidly coupled to the wellhead.
 18. Thesystem of claim 17 wherein the natural gas source comprises at least oneLNG tank, the natural gas pump comprises a high pressure natural gaspump, and the system further comprises a heater component fluidicallycoupled to an outlet of the high pressure natural gas pump.
 19. Thesystem of claim 17 further comprising at least one controllercommunicatively connected to one or more of the liquid base fluid pump,the natural gas pump, the mixer, and/or one or more valves fluidicallyconnected to one or more of the liquid base fluid source, the naturalgas source, and the unreactive gas source.
 20. The system of claim 17wherein the system does not comprise a flare in fluid communication withthe wellhead.